Well tool

ABSTRACT

A subsurface safety valve well tool adapted to be positioned in the bore of a production tubing for controlling flow of fluid through the bore of the tubing by rotating a ball valve to and from open and closed positions in response to a series of sequential pressure changes in the bore of the tubing.

0 I United States Patent 1191 1111 3,821,962 M611 1451 July 2, 1974 [54] WELL TOOL 3,002,566 10/1961 Bostock 166/224 8 3 8 62 P 6 4 [75] memo James Houston 31%21552 2ii 66 511 14349: 7 I 3,3l0,l l4 3/1967 Dollison l66/224 3] Asslgnee Company Los Angeles 3,568,768 3/1971 Rowell 137/461 x [22] Filed: Jan. 3, 1972 Primary ExaminerHarold W. Weakley 2 APPL 4 7 Attorney, Agent, or Firm-Pravel, Wilson & Matthews [52 us. 01 137/12, 137/458, 251/58 [571' ABSTRACT [51] Int. Cl. Fl6k 17/20 Subsurface safety valve well tool adapted to be posi- [58] Field of Sear h 166/224, 224 S; 251/53; tioned in the bore of a production tubing for control- 137/358, 494, 461, 458, l2 ling flow of fluid through the bore of the tubing by retating a ball valve to and from open and closed posi- [56] Ref r Cit d tions in response to a series of sequential pressure UNITED STATES PATENTS changes in the bore Of the tubing.

2,998,077 8/1961 Keithahn 251/58 X 11 Claims, 21 Drawing Figures PATENYEBJUL 21974 SHEU '4 UF 9 a 7 vi itr lr lniiir BACKGROUND OF THE INVENTION This invention relates to the field of a subsurface safety valve well tool.

The use in production tubings of automatic subsurface safety valves having a reference pressure chamber operated rotatable ball-type bore closure member for controlling dangerous and costly well blowouts is known. These valves have operated by comparing the pressure in the chamber with the pressure in the bore of the tubing to close the valve when the pressure in the bore was less than the pressure established in the reference chamber. For efiicient well production, the pressure in the reference chamber had to be set to close the valve when the well pressure was substantially less than the normal well flowing pressure. This arrangement requires an abnormally large flow, such as that which occurred at a well blowout, to lower the pressure in the tubing sufficiently to close the valve. While these valves only functioned to close the flow through the bore after a blowout had occurred, they often would not function at all in wells having a high allowable rate of production. Also, these valves lacked means to shut-in the well at the subsurface location when the surface located well control apparatus operated to shut-in the well. Subsequent damage to the shut-in surface control apparatus, such as that which recently occurred by fire on a multiple well offshore platfonn, would enable the well to blow out before operating these valves to shutin the well.

An object of the present invention is to provide a new and improved well tool.

Another object of the present invention is to provide a new and improved pressure responsive subsurface safety valve.

Yet still another object of the present invention is to provide a new and improved pressure responsive subsurface safety valve that may be installed or retrieved through the bore of the well tubing.

SUMMARY OF. THE INVENTION A subsurface safety valve well tool having a rotatable ball-type valve bore closure means mounted with a flow control assembly is run through and secured in the bore of a production tubing for controlling flow of fluid through the bore of the tubing. The ball valve is moved to and locked in the open position for enabling flow of fluid through the bore of the tubing by means with the flow control assembly actuated by sequentially increasing and then decreasing the pressure in the bore of the tubing above the valve. A subsequent sequential change in the pressure in the bore of the tubing from a pressure less than a preselected well pressure to a pressure greater than the preselected well pressure moves a pressure responsive piston to release the ball valve and enable a spring means to move the ball valve to the closed position to block flow of fluid through the bore of the tubing. The flow control assembly is provided with a means for equalizing the urging of the well pressure thereon to enable a larger flow passage through the bore of the tubing.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a side view, in section, illustrating the subsurface location of the safety valve of the present invention in a well production tubing;

FIGS. 2A, 2B, 2C, and 2D are side views, partially in section, from top to bottom of the safety valve of the present invention;

FIGS. 3A and 3B are side views, partially in section with a pressure charge in the reference chamber;

FIGS. 4A and 4B are views similar to FIGS. 3A and 33, respectively, illustrating the safety valve in the closed position;

FIGS. 5A, 5B, and 5C are side views, partially in section, illustrating movement of the safety valve to the open position;

FIGS. 6A, 6B, and 6C are views similar to FIGS. 5A, 5B, and 5C illustrating the safety valve in the open position;

FIG. 7 is a side view, in section, illustrating movement of the plunger detents for operating the safety valve;

FIGS. 8, 9 and 10 are views taken along lines 8-8, 9-9, and 10-10, respectively, of FIG. 2C; and

FIGS. 11 and 12 are side views illustrating rotation of the valve ball member.

DESCRIPTION OF PREFERRED EMBODIMENT Attention is directed to FIG. 1 where the well tool S of the present invention is illustrated secured at a subsurface in the longitudinal bore J of the production tubas is well known in the art. A valve, designated at 20,

is located on a Christmas Tree X at the surface G for normally controlling the flow of fluid through the bore J of the tubing T.

The ,tool S is connected to a suitable tubular mandrel 21 for securing the tool S in the bore J of the tubing T. The mandrel 21 is well known in the art, and is designed to secure and packoff wire-line retrievable subsurface well tools in the bore J of the well tubing T. Examples of a readily available mandrel 21 would be either a Type C mandrel mandrel or a Type D collar mandrel, manufactured by Otis Engineering Corporation of Dallas, Texas. If the Type D mandrel is selected, latch dogs are employed to lock into a recess in the bore of the tubing adjacent a threaded tubing connection to secure the mandrel in the bore of the tubing. The Type C mandrel, illustrated in FIG. 1, employs slips 21a to secure the tubular mandrel 21 at any location in the bore J of the tubing T. A packing ring 21b seals between the outer surface of the mandrel 21 and the inner surface of the bore J of the tubing T to block the flow of fluid therebetween and to direct flow through the bore of the mandrel 21.

g The tool S includes a flow control assembly, generally designated F, and a bore closure means B (FIG. 2D) mounted therewith for controlling flow through the bore J of the tubing T. Sequentially increasing and then decreasing the pressure in the bore of the tubing T above the bore closure means B operates the tool S to open the bore closure means B to enable flow through the bore J of the tubing T. The initial increase in the pressure in the bore moves the bore closure means B and a movable lower portion of the flow control assembly F downwardly where the movable portion is locked to block movementrelative to the remainder of the flow control assembly F. The following decrease in pressure in the bore enables a spring member to urge the bore closure means B to move upwardly relative to the lower locked portion of the flow control assembly F to move to the open position to enable flow through the bore of the tubing.

With the bore closure means B in the open position, a decrease with a subsequent increase in the pressure in the bore J of the tubing T operates the tool S to move the bore closure means B to the closed position to block flow through the bore J of the tubing T. A pressure responsive member is biased by a charged pressure when the well pressure is decreased below the preselected pressure to move to engage the mechanism locking the movable portion of the flow control assembly F from movement. The subsequent increased pressure above the preselected pressure in the bore of the tubing T moves the pressure responsive member upwardly to release the locked portion of the flow control assembly F. The lower portion of the flow control assembly F moving upwardly rotates the bore closure means B to the closed position.

As illustrated in greater detail in FIGS. 2A, 2B, 2C, and 2D, the flow control assembly F includes an elongated tubular member 31,-a fluid pressure reservoir means 32, a movable slide means 33 and a piston means 71. The upper end of the tubular member 31 (FIG. 2A) includes suitable threads 31a to engage the mandrel 21 for securing the well tool S in the bore J of the tubing T. Since the threads 31a also seal the tubular member 31 with the mandrel 21, the flow of fluid through the bore J of the tubing T is also directed through a longitudinal bore 35 extendingthe length of the tubular or carrier member 31. The fixed tubular member 31 extends downwardly from the threads 31a to provide support for the operating mechanisms of the well too] S as will be set forth in greater detail hereinafter. The tubular member 31 includes a seal ring 31c concentrically secured thereto adjacent the lower-end (FIGS. 2C and 2D) by threaded engagement at 31b.

The pressure reservoir means 32 (FIGS. 2A and 2B) for containing a charged reference fluid pressure for biasing movement of the piston means,7l includes a snap ring 320, a plurality of connected sleeves 32b, 32c and 32d and a diaphragm 34. The snap ring 32a (FIG. 2A) is located within a recess 3111 in the outer surface of the tubular member 31 for securing the reservoir means 32 with the tubular member 31. For ease of assembly, the base sleeve 32b and the cap sleeve 32c are secured together about the snap ring 32a by threaded engagement at 32e while the reservoir sleeve 32d is secured with the sleeve 32b by threaded engagement at 32f. The secured sleeves 32b and 32c surround the protruding portion of the ring 320 to block longitudinal movement of the pressure reservoir means 32 along the tubular member 31. Engagement of the tapered upper surface 32g of the ring- 32a with the sleeve 32c maintains a portion of the ring 32a in the recess 31b of the member 31.

Disposed within the concentric annular space formed between the sleeve 32d and the tubular member 31 is the flexible diaphragm member 34 for containing an operating fluid at a charged pressure within the pressure reservoir means 32. The lower end of the diaphragm member 34 (FIG. 2B) is sealed to the sleeve 32d with an O-ring 34a located in a recess in the outer surface of a ring member 34b to prevent the escape of fluid therebetween. A ring member 3412 at the upper end of the diaphragm 34 (FIG. 2A) is secured to the sleeve 32b by threads 34c for securing the diaphragm 34 in the pressure reservoir means 32. The diaphragm 34 is sealed to the tubular member 31 for preventing the escape of the charged fluid therebetween by an O- ring 340 located in a recess in the member 346. The sleeves 32b and 32d and the diaphragm 34 thus form a pressure chamber of reservoir 37 defined in greater detail by portions of the inner surface of the sleeve 32d, a portion of the lower shoulder of the sleeve 32b and the outer surface of the flexible diaphragm 34. The flexible diaphragm 34 enables the chamber 37 to expand and contract in response to the pressure acting on the diaphragm 34.

As illustrated in FIG. 2A, the pressure reservoir means 32 also includes a means for filling or pressurizing'the reservoir 37. The means for filling the reservoir includes a threaded refill connection port 35a communicating through channels 35b and 35c in the sleeves 32c and 32d, respectively, with a port opening 34f in the upper diaphragm ring member 34s. A flapper member 35d secured at one end to the sleeve 32b opens to allow communication or flow through the port 34f into the reservoir 37 by flexing away from the opening 34f, but closes to prevent flow out of the reservoir 37 through the port 34f.

The flow control assembly F also includes the pressure reservoir plunger or piston means 71 (FIGS. 28 and 2C) concentrically mounted with the tubular member 31 below the pressure reservoir means 32 which moves longitudinally in response to the pressure in the bore J of the tubing T and the reservoir 37 to control operation of the well tool S. Preferably, for ease of assembly the plunger 71 is made in two sleeve portions with the upper portion 71a secured to the lower portion 71b by thread engagement at 71c. The upper portion 71a extends upwardly into the annular space between the tubular member 31 and the reservoir sleeve 32d to form an upwardly facing reference pressure sensing effective surface area 71d. The portion of the pressure reservoir means 32 adjacent the pressure responsive surface 71d forms a chamber 74, defined generally by the inner surface of the diaphragm 74 and the outer surface of the member 31, which is filled with oil or another incompressible fluid for transmitting the urging of the charged pressure in the chamber 37 to the surface 71d for urging the plunger 71 to move downwardly in response thereto. The piston 71 mounts a pair of 0- rings 71e and 32b to seal with the tubular member 31 and the sleeve 32d, respectively, to prevent the escape of oil from the chamber 74. The plunger 71 includes a port 71f formed therethrough for communicating the pressure in the bore J of the tubing T to a downwardly facing well pressure sensing efiective surface 71g for urging the plunger 71 to move upwardly into the chamber 74 in response to the pressure in the bore J of the tubing T.

As illustrated in FIGS. 2C and 2D, the flow control assembly F includes a slide 33 for effecting movement of the bore closure means B which is movably mounted with the tubular member 31 below the piston means 71.

The slide 33 is preferably formed of an elongated tubular member concentrically mounted about the exterior of the tubular member 31 and comprising four sleeve portions 33a, 33b, 33c and 33d, secured together by threaded engagement or other suitable fastening means. The slide member 33 is movable relative to the tubular member 31 between an upper position (FIGS. 2C and 2D) and a lower position (FIGS. 5B,5C,6B, and 6C). The connected sleeves 33a, 33b,. 33c and 330', form a longitudinal bore 36 extending through the slide 33 for communicating therethrough flow of fluid through the bore .1 of the tubing T and having a recess 33e formed in the sleeve 33a for receiving a member to lock the slide 33 in the lower position to maintain the bore closure means B open.

The bore closure means B is movably disposed in the bore 36 of the slide 33 below the tubular member 31 adjacent the sleeve portion 330. The bore closure means B includes a rotatable ball-type valve having a longitudinally movable seat ring 41 positioned above a ball member 40. The ball 40 has a bore 40a therethrough for enabling flow of fluid through the bore J of the tubing T when in the aligned or opened position (FIG. 6C) and which is rotatable to a transverse or closed position (FIG. 2D) for blocking flow of fluid through the bore .1 of the tubing T. The ball 40 includes an outer spherical surface 40b having a pair of machined parallel flat surface portions 40c with each of the fiat surfaces 400 having an elongated recess 40d (FIGS. 11 and 12) formed therein for receiving a pivot member to impart rotation to the ball 40. The seat ring 41 includes a lower annular seating surface 41a engaging the spherical surface 40b of the ball 40 for sealing thereto to block upwardly flow of fluid through the bore 36 fo the slide 33 around the ball 40 and an upper annular shoulder 41b engaging the fixed seal ring member 31c for limiting upward movement of the seat ring 41 and the ball 40. The seat ring 41 is movable relative to both the slide 33 with an O-ring 41c for blocking flow of fluid between the seat ring 41 and the slide member 33.

The flow control assembly F also includes means for effecting mvoement of the ball 40 to and from the open and closed positions in response to pressure changes in the bore J of the tubing T. In addition to the slide 33 and the seat ring 41, the means for effecting movement of the bore closure means B to the open position includes a pivot means 43 and an operator or actuator means 44. The pivot means includes a pair of pins 43a (FIG. 2D) secured with the sleeve 33c of the slide 33 on a common longitudinal axis and which extend into corresponding recesses 40d in the flat surfaces 40c of the ball 40 and which are preferably threaded into the sleeve 33c for ease of assembly of the tool S. Longitudinal relative movement between the ball 40 and the pins 430 will effect rotation of the ball 40 to and from the open position (FIG. 11) and closed position (FIG. 12) with the longitudinal distance the center of the ball 40 moves upwardly relative to the pins 43a to effect rotation of the ball 40 to the open position illustrated in FIG. 11 while the longitudinal distance the center of the ball 40 moves downwardly to effect closing rotation of the ball 40 illustrated in FIG. 12. Reference is made to my co-pending application Ser. No. 72,034, filed Sept. 14, 1970, entitled PRESSURE OPERATED SAFETY VALVE WITH LOCK MEANS, for a more detailed description of the rotation of the ball 40 about the eccentric pins 430.

Disposed concentrically in the bore of the slide 33 adjacent the sleeves 33c and 33d is the actuator 44 for effecting the required longitudinal mvoement of the ball 40 to co-act with the pins 43a for rotating the ball 40. The actuator or sleeve 44 includes an upper annular shoulder 44a engaging the lower portions'of the spherical outer surface 40b of the ball 40 for imparting an upward urging on the ball 40 and a collar 44b formed thereon having a lower flat spring shoulder 44c and an annular tapered shoulder 44d engaging the tapered inner shoulder 33g of the slide 33 to provide a lower movement limit stop for the sleeve 44. A spring means Me is positioned between an annular shoulder 33f of the slide 33 and the shoulder 440 for imparting the upward urging to the sleeve 44.

The means for effecting movement of the ball 40 to the closed position when the pressure in the bore J of the tubing T is increased above the preselected well pressure includes the slide 33, the pivot pins 43a, and a spring means 50. The spring means 50 (FIG. 2C) is concentrically mounted about the tubular member 31 between the ring member 310 and a gapped ringshaped keeper member 50a which engages the sleeve 33a for imparting the upwardly urging of the spring 50 to the slide 33. The spring 50 is substantially stronger than the spring 44d and will over come the urging of the spring 44d to move the slide 33 upwardly to effect closing rotation of the ball 40 and will normally maintain the slide 33 in the upper position.

As illustrated in FIG. 6B, the means for releasably locking the ball 40 in the open position includes the recess 33e formed in the slide 33, a plurality of detent balls and a locking sleeve 61. The tubular member 31 on a slotted raised outer portion 31d threadedly engages and secures thereto a fixed spaced concentric sleeve 31e having a plurality of window openings 31f (FIG. 8) for receiving the plurality of detent balls 60 therein. The locking sleeve 61 is longitudinally movable between an upper position and a lower position for locking the detent balls 60 in the recess 332 and which is normally biased downwardly by a spring 61a located above the sleeve 61 and concentrically mounted with the tubular member 31 by a spring keeper member 61b secured with the tubular member 31. As illustrated in greater detail in FIG. 9, the sleeve 61 has a plurality of longitudinal windows or slots 61e formed therein extending upwardly from a tapered lower annular shoulder 61c to provide movement enabling clearance about the nonslotted raised portions 31d of the tubular member 31.

A slotted collar 31g (FIG. 10) extends outwardly from the tubular member 31 through the slot 61e in the sleeve 61 to engage a downwardly facing shoulder 61f formed by the upper end of the slot 61e to provide a lower movement limit stop when the sleeve 61 is in the lower position. When the recess 336 in the slide 33 is aligned with the plurality of ball detents 60, which have a greater diameter than the wall thickness of the fixed sleeve 332, the spring 61a urging the sleeve 61 to move downwardly wedges or forces the balls 60 outwardly into the recess 33e with a tapered lower annular shoulder 610 which enables the sleeve 61 to move downwardly beside the balls60 to lock the balls in the recess 33e (FIGS. 5B and 6B) and thereby lock the slide 33 in the lower position. An upward movement imparted to the sleeve 61 to move the shoulder 61c above the plurality of detents 60 enables the detents 60 to move out of the recess 33e and thereby releases the slide 33 enabling the upwardly urging imparted by the spring 50 to move the slide 33 upwardly to effect movement of the ball 40 to the closed position for blocking the flow through the bore J of the tubing T.

The release of the slide 33 by the sleeve 61 is effected by the piston 71 moving upwardly in response to the pressure in the bore J of the tubing T. The piston 71 has a plurality of windows 71h formed therein which are uniformly circumferentially spaced about the piston 71 (FIG. 2C). Located in the windows 71h are a corresponding plurality of detent balls 73 having a greater diameter than the thickness of the piston sleeve 71 adjacent the windows 7111. The flow control assembly F includes a movable latch slide measn'72 comprising a concen-rically mounted sleeve 72 having an annular recess 72a formed in the inner surface into which the balls 73 move into when aligned therewith and which locks the detent balls 73 inan annular recess 61d of the sleeve 61 for connecting the locking sleeve 61 with the piston 71 to move the sleeve 61 upwardly with the piston 71. The slide 72 has an inwardly extendingcollar 72b for engaging the unslotted portion of the collar 31g to provide an upper limit stop for the slide 72. The slide 72 is biased by a spring means 720 positioned between the collar 72b and the fixed sleeve 31c for providing an upwardly urging to the sleeve 72. The movable latch 72 is sealed by a pair of O-rin'gs 72d and 72e to the plunger 71 and the sleeve 31e, respectively, for preventing the flow of fluid around the latch 72.

The well tool S also includes a means for reducing the well tool wall thickness by equalizing the urging of the well pressure on the flow control assembly F to produce a larger flow passage through the bores 35 and 36 of the well tool S. The means for equalizing the urging of the well pressure includes a balance member or piston 81 and a balance chamber 82. The balance piston 81 is a ring shaped member positioned in the annular space between the tubular member 31 and a recessed inner surface 711' of the piston sleeve 71 below the port 71f and is longitudinally movable relative to both the plunger 71 and the tubular member 31 in response to pressures acting thereon. The balance member 81 is sealed by a pair of O-rings 81a and 81b and to the plunger 71 and the tubular member 31, respectively for preventing flow of fluid therebetween. The annular balance chamber 82 (FIG. 2B and 2C) is fonned in the flow 'control assembly below the balance member 81 and is partially defined in greater detail by the surface of the tubular member 31 including the upper shoulder of the seal ring 310, the upper portion of the slide 33, the fixed sleeve 31a, the latch slide 72 and the lower portion of the plunger 71. The balance member 81 includes a downwardly facing annular shoulder 81c forming the upper portion of the chamber 82 to provide a pressure responsive surface on the balance member 81 for urging upwardly movement of the balance member 81 in response to the pressure in the chamber 82. The balance member 81 includes an upwardly facing annular surface 81d for urging downward movement of the balance member 81 in response to the pressure urging on the surface 81d. By filling the chamber 82 with an incompressible fluid such as hydraulic fluid or oil, the pressure of the fluid in the chamber 82 will be maintained equal to the pressure in the bore of the tubing T communicated through the port 71 f by movement of the balance piston 81. The chamber 82 thereby provides a protected environment for the moving parts in the chamber 82 as well as eliminating any stresses on the flow control assembly F induced by a pressure differential across a member. Only the tubular member 31, the seat ring 41, and the ball 40 need be made with sufficient thickness to hold the pressure in the bore of the tubing T when the ball 40 is rotated closed. It will immediately be appreciated that this thin wall construction thus provides a larger flow passage through the bore J of the tubing T.

In the use and operation of the present invention, the well shut in pressure and the well flowing pressure at the subsurface location where the tool S is to be secured in the bore J of the tubing T is first determined. The well flowing pressure will always be less than the well shut in pressure by some value. For example, the well flowing pressure at the subsurface location may be 2500 psi and the shut-in pressure may be 3000 psi. An intermediate well pressure, for example, 2750 psi, would then be chosen as the preselected well pressure to effect operation of the well tool S. For simplicity of description,-the effective surface area of the reference chamber piston surface 71d and the well pressure shoulder surface 71g on which the pressures urge on the piston 71are considered to be equal, hence the reference pressure to be established in the pressure reservoir 37 is identical to the preselected well pressure. One skilled in the art may vary the ratio of these effective surface areas and hence vary the actual pressure charged in reservoir 37 from the preselected pressure. The compressed gas or vapor, preferably nitrogen to prevent deterioration of the rubber diaphragm 34, is injected or charged into the system at port 35a to pressure the chamber 37. The flow of nitrogen is communicated through the channels 35b and 350 to the port 34f and into the chamber 37. The flapper member 35d enables the flow of nitrogen into the chamber 37, but moves to block the flow of nitrogen from the chamber 37 through the port 34f to maintain the charged pressure in the chamber 37.

When the pressure charge has been established in the chamber 37 and the supply of compressed gas is disconnected, the tool 20 is in the condition illustrated in FIGS. 3A and 3B. The plunger 71 has been moved downwardly from the upper or retracted position (FIGS. 2B and 2C) to the lower or extended position illustrated by the greater charged pressure. The gas pressure in the chamber 37 has also flexed the diaphragm 34 to move inwardly to fill the portion of the chamber 74 not filled with oil. The urging of the charged pressure in the chamber 37 is transmitted through the oil in the chamber 74 to the piston surface 71d for urging the plunger 71 to move downwardly to the extended position.

As the piston 71 moves downwardly, the detent balls 73 mounted with the piston 71 engage the lower surface of the recess 72a for moving the latch sleeve 72 downwardly along with the plunger 71. The downward movement of the latch sleeve 72 continues until the detent balls 73 align with an annular recess 61d formed in the locking sleeve 61 (FIG. 7). The upward urging of the spring 720 on the latch sleeve 72 will then wedge the detent balls 73 with the tapered edge of the recess 72a to move inwardly into the recess 61d. This releases the latch sleeve 72 from engagement with the plunger 71 and enables the urging of the spring means 720 to move the latch sleeve 72 upwardly to the position illustrated in FIG. 38 with the detent balls 73 extending into the recess 61d.

The tool is then connected with the mandrel 21 and the connected assembly is run down the bore of the production tubing T to the desired subsurface position for securing the tool S in the bore J of the tubing T, as illustrated in FIG. 1. The mandrel 21 is then secured in the bore of the tubing T by the slips 21b and the wireline running tool retrieved as is well known in the art.

With the surface control valve 20 of the Christmas Tree X closed, the well shut-in pressure is communicated through the port 71 f to the surface 71g to urge the piston 71 to move upwardly. The shut-in pressure communicated through the port 71f also urges on the upper shoulder of the balance piston 81 to urge the balance piston to move downwardly to maintain the pres sure in the chamber 82 filled with oil equal to the well shut-in pressure. This eliminates any pressure differential across the slide 33, the sleeve 312, the latch 72 or the piston 71 which would damage, induce stresses, or otherwise interfere with their operation.

Because the charged pressure established in the chamber 37 for urging downwardly on the surface 71d is less than the well shut-in pressure urging on the surface 7lg to move the plunger 71 upwardly, the plunger 71 moves upwardly to the position illustrated in FIGS. 4A and 4B. The upward movement of the plunger 71 also moves the locking sleeve 61 upwardly by engagement of the detent balls 73 in the recess 61d until the balls 73 are aligned with the annular recess 72a in the latch 72. The downward biasing of spring 61a on the locking sleeve 61 forces or wedges the balls 73 out of the recess 61d and into the recess 72a to release the sleeve 61 from the plunger 71. The locking sleeve 61 is then free to be moved downwardly by the biasing of spring 61a with the detent balls 73 remaining in the recess 72a as illustrated in FIG. 4B. The sleeve 61 moves downwardly until the lower tapered annular shoulder 61c engages the lower detent balls 60. v

To rotate the ball 40 to the open position for enabling fluid to flow through the bore J of the tubing T, apump or other pressure generating means is connected to the bore J of the tubing T at the surface G. The pressure in the bore J of the tubing T above the ball 40 is then increased until it is greater than the shut-in pressure of the well. The increased pressure produces a pressure differential across the ball 40 and the seat ring 41 to create a downwardly urging thereon which overcomes the upwardly urging of the spring 50 to move the ball 40, the seat ring 41, and the slide 33 downwardly relative to the stationary tubular member 31. The downwardly urging produced by the increased pressure is transmitted through the sleeve 44 to the slide 33 at engaged annular shoulders 44d and 33g.

As illustrated in FIGS. 58 and C, the downward movement of slide 33 aligns the annular recess 33e with the detent balls 60 located in the window openings 31f. When the recess 33e is aligned with the balls 60 the biasing of the spring 61a urging the latch sleeve 61 downwardly wedges the balls 60 outwardly into the recess 33e with the-tapered lower surface 610 engaging the balls 60. The latch 61 continues to move downwardly beside the balls 60 for locking the balls 60 in the recess 33e with the outer surface of the sleeve 61. With the 10 balls 60 locked in the recess 33e, the slide 33 is blocked from moving upwardly by the urging of spring 50 by engagernent of the tapered lower surface of the recess 33e with the balls 60 in the window 31f. As illustrated in FIG. 5A the piston 71 has the same shut-in pressure and charged reservoir pressures urging thereon and has not moved even though the pressure in the tubing T above the ball 40 has beeen increased. However, the

balance member 81, to maintain the pressure in the chamber 82 equal to the well pressure, moves to compensate for any change in volume of the chamber 82 by the movement of the slide 33.

After locking the slide 33 in the lower position with the balls 60, the ball 40 is rotated to the open or aligned position, illustrated in FIG. 6C, by venting or otherwise decreasing the pressure in the bore J of the tubing T above the tool S. The reduced pressure urging downwardly on the ball 40 and the seat ring 41 enables the urging of the spring 44e to move the sleeve 44 upwardly. The upward movement of the sleeve 44 also moves the engaged ball 40 and seat ring 41 upwardly relative to the slide 33.

The movement of ball 40 relative to the slide 33 also moves the ball 40 relative to the pivot pins 43a secured with the slide 33 to impart a rotation to the ball 40 for rotating the ball 40 to the aligned position. FIG. 11 illustrates in greater detail the relationship of the pins 43a and the ball 40 in rotating the ball 40 to the aligned position from the closed position. The sleeve 44, the ball 40, and the seat ring 41, move upwardly until the upper shoulder 41b of the seat ring 41 engages the ring member 31c secured to the tubular member 31.

With the ball 40 in the aligned position hydrocarbons and the like in the producing formation F flow through the bore J of the production tubing T to the surface G. The valve 20 on Christmas Tree X is used to establish normal producing flow through the bore J of the tubing T thereby reducing the well pressure in bore J of the tubing T to the normal well flowing pressure which is less than the pressure established in the reservoir 37.

With the well flowing pressure for urging the piston 71 to move upwardly less than the downwardly urging on the piston 71 provided by the charged pressure downwardly movement of the piston 71 from the upper position (FIG. 6A) to the lower position (FIG. 3B) is effected. The downwardly movement of the plunger 71 also moves the latch slide 72 downwardly by engagement of the balls 73 locked in the recess 72a. The latch sleeve 72 moves downwardly with the plunger 71 until the balls 73 are aligned with recess 61d in the latch sleeve 61 (FIG. 7). When aligned with the recess 61d the lower tapered surface of the recess 72a will wedge the balls 73 inwardly to effect movement of the balls 73 into the recess 61d. The movement of the balls 73 into the recess 61d disengages theballs from the recess 7 2a and enables the spring 720 to return the latch sleeve 72 to the upper position. This movement of the latch sleeve 72 also locks the balls 73 in the recess 61d to thereby operably connect the piston 71 and the locking sleeve 61.

When the valve 20 on the Christmas Tree X at the surface G is closed the pressure in the bore of the tubing T increases from the well flowing pressure to the well shut-in pressure. The greater shut-in pressure urging on the piston 71 overcomes the downwardly urging on the piston 71 to move the piston 71 upwardly. The upwardly movement of the piston 71 engages the detent balls 73 with the upper tapered edge of the recess 61d to overcome the downward urging of the spring 61a to move the sleeve 61 upwardly along with the piston 71. The upwardly movement of the sleeve 61 moves the lower edge 610 above the detent balls 60 to enable movement of the balls 60 from the recess 33e in the slide 33. With the balls 60 no longer locked in the recess 33e the balls 60 are wedged inwardly by the tapered edge of the recess 33e and the slide 33 is moved upwardly by the urging of the spring 50.

The seat ring 41 engaging the fixed member 310 blocks upwardly movement of the ball 40 which enables the eccentric pins 430 secured with the slide 33 to move upwardly relative to the ball 40 to impart a rotation to the ball 40 to rotate the ball 40 90 from the open position '(FIG. 6C) to the closed position (FIG. 2D). The movement of the ball 40 to the closed position from the open position (phantom) is illustrated in greater detail in FIG. 12 with the arrow designating the direction of the relative movement of the center of the ball 40 to the pins 43a. The relative longitudinal movement between the pins 430 and the ball 40 is the same as if the ball 40 was moved downwardly relative to the pins 43.

With the ball 40 in the closed position, the flow of fluid in the bore of the tubing T is blocked at both the subsurface location and at the well surface. Should the surface G located control equipment be subsequently destroyed by fire or the like, the well tool S will continue to block flow through the bore J of the tubing T and prevent a blowout. When it is desired to produce from the well again, it is only necessary to sequentially increase and then decrease the pressure in the bore of the tubing T about the well tool S to rotate open the ball 40 in the manner set forth above. A subsequent decrease to flowing pressure will again cock the well tool S to enable rotation of the ball 40 to the closed position when the pressure in the bore increases to the shut-in pressure.

If the well tool S malfunctions, the well too] S and the mandrel 21 may be retrieved back to the surface with a wire-line retrieval tool. A properly operating well tool S may then be run in the bore J of the tubing T, without the need to kill the well and pull the tubing T to replace the well tool S. While the preferred embodiment of the present invention is a wire-line run and retrieved safety valve, the invention may be employed without that feature by simply securing the tool S in the'bore J of a tubing joint which would then be included in the flow control housing F. The tubing joint forming a portion of the flow control assembly F would then be connected in the well tubing string at the desired location.

The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the size, shape, and materials, as well as in the details of the illustrated construction, may be made without departing from the spirit of the invention.

What is claimed is:

l. A method of operating a subsurface safety valve located in a well tubing for controlling flow of well fluids through the bore of the tubing, including the steps of:

increasing the well fluid pressure in the bore of the well tubing sensed by the valve above a preselected pressure for closing the valve.

2. The method as set forth in claim 1, including the step of:

blocking flow from the well tubing to increase the pressure in the well for closing the valve.

3. The method as set forth in claim 1, including the step of:

decreasing the well fluid pressure in the well tubing sensed by the valve below the preselected pressure prior to the step of increasing the well fluid pressure in the well tubing to close the valve.

4. The method as set forth in claim 1, including the step of:

decreasingthe pressure in the well tubing sensed by the valve below the preselected pressure to actuate the valve for enabling closing of the valve prior to the step of increasing the pressure in the well tubing to close the valve.

5. The method as set forth in claim 1, including the step of:

rotating a bore closure member of the safety valve to close the valve when the sensed well fluid pressure in the bore of the well tubing is increased.

6. The method as set forth in claim 1, including the steps of: v

a. increasing the pressure in the well tubing above the valve to a pressure value greater than the well pressure below the closed valve for actuating the valve to enable opening thereof; and

b. subsequently decreasing the pressure in the well tubing above the valve for opening the valve.

7. A method for controlling operation of a subsurface safety valve located in a well tubing for selectively enabling flow of fluid through the bore of the tubing includes the steps of:

a. decreasing the fluid pressure in the well tubing sensed by the subsurface valve below a preselected pressure for actuating the valve to enable closing; and

b. increasing the pressure in the well tubing sensed by the subsurface valve to a value above the preselected pressure for closing the valve.

8. The method as set forth in claim 7, including the step of:

rotating a bore closure member of the safety valve to close the valve.

9. A method of controlling flow of fluid through a bore of a well tubing having a subsurface safety valve located therein including the steps of:

- a. increasing the pressure in the bore of the well tubing above the valve to' actuate the valve to enable opening thereof; and

b. decreasing the pressure in the bore of the tubing above the valve sufiiciently to open the valve for enabling flow of fluid through the bore of the tub- 10. The method as set forth in claim 9 including the step of:

rotating a bore closure member of the valve to open.

the valve for enabling flow of fluid through the bore of the tubing.

11. The method as set forth in claim 9 including the steps of:

a. decreasing the pressure in the bore of the tubing sufficiently to actuate the valve to enable closing of the valve; and

b. increasing the pressure in the bore of the tubing above the valve for closing the valve to block flow of fluid through the bore of the tubing. 

1. A method of operating a subsurface safety valve located in a well tubing for controlling flow of well fluids through the bore of the tubing, including the steps of: increasing the well fluid pressure in the bore of the well tubing sensed by the valVe above a preselected pressure for closing the valve.
 2. The method as set forth in claim 1, including the step of: blocking flow from the well tubing to increase the pressure in the well for closing the valve.
 3. The method as set forth in claim 1, including the step of: decreasing the well fluid pressure in the well tubing sensed by the valve below the preselected pressure prior to the step of increasing the well fluid pressure in the well tubing to close the valve.
 4. The method as set forth in claim 1, including the step of: decreasing the pressure in the well tubing sensed by the valve below the preselected pressure to actuate the valve for enabling closing of the valve prior to the step of increasing the pressure in the well tubing to close the valve.
 5. The method as set forth in claim 1, including the step of: rotating a bore closure member of the safety valve to close the valve when the sensed well fluid pressure in the bore of the well tubing is increased.
 6. The method as set forth in claim 1, including the steps of: a. increasing the pressure in the well tubing above the valve to a pressure value greater than the well pressure below the closed valve for actuating the valve to enable opening thereof; and b. subsequently decreasing the pressure in the well tubing above the valve for opening the valve.
 7. A method for controlling operation of a subsurface safety valve located in a well tubing for selectively enabling flow of fluid through the bore of the tubing includes the steps of: a. decreasing the fluid pressure in the well tubing sensed by the subsurface valve below a preselected pressure for actuating the valve to enable closing; and b. increasing the pressure in the well tubing sensed by the subsurface valve to a value above the preselected pressure for closing the valve.
 8. The method as set forth in claim 7, including the step of: rotating a bore closure member of the safety valve to close the valve.
 9. A method of controlling flow of fluid through a bore of a well tubing having a subsurface safety valve located therein including the steps of: a. increasing the pressure in the bore of the well tubing above the valve to actuate the valve to enable opening thereof; and b. decreasing the pressure in the bore of the tubing above the valve sufficiently to open the valve for enabling flow of fluid through the bore of the tubing.
 10. The method as set forth in claim 9 including the step of: rotating a bore closure member of the valve to open the valve for enabling flow of fluid through the bore of the tubing.
 11. The method as set forth in claim 9 including the steps of: a. decreasing the pressure in the bore of the tubing sufficiently to actuate the valve to enable closing of the valve; and b. increasing the pressure in the bore of the tubing above the valve for closing the valve to block flow of fluid through the bore of the tubing. 